Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir; by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore has been drilled, the well must be completed before hydrocarbons can be produced from the well. A completion involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, production of oil and gas can begin.
The completion can include operations such as the perforating of wellbore casing, acidizing and fracturing the producing formation, and gravel packing the annulus area between the production tubulars and the wellbore wall. For use in multi-zone completions where it is required to perform fracture stimulation treatments on separate zones.
Likewise, when a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Holes (perforations) are placed to penetrate through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing consists of injecting fluids (usually viscous shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the pressure is released. Increased flow capacity from the reservoir results from the easier flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods.
A typical approach is to drill and case with cement through the various zones of interest. Then the operator will work from the bottom of the well or from the lowest production zone:
1. Perforate zone;
2. Fracture or stimulate zone;
3. Flow back and clean-up debris in the production test zone.
4. Plug the zone to keep it isolated.
There are numerous plugs that can be used, including, but not limited to, a cast iron bridge plug (which is drillable); a retrievable bridge plug (which is retrievable); a composite bridge plug (which is drillable); a cement plug; and/or the like.
In general, the process is repeated going back uphole at each production zone where production is desired. There can be as few as one zone and an infinite maximum number of zones. Typically, at the uphole most zone, the step of plugging the zone is skipped.
To begin production from all of the plugged zones, a drill string is lowered with a mill or cutter to mill or drill through all the various plugs at the different zones, wherein all milled zones are allowed to be in communication with the wellbore.
The completion is then set in the wellbore and the well put on production. In various embodiments, a completion is as simple as production tubing terminated into a packer above the top zone. Or, it could consist of a series of packing placed between each set of parts connected by tubing with valves in between. The valves or controllers are capable of being wireline operable, sometimes called sliding sleeves or sliding side doors, or they could be remotely operated valves that depend on a series of hydraulic or electric, or both control lines, typically called interval control valves (ICVs).
Regardless of completion type, what is found is that: the overall production rate and remainder obtained after production are universally less than what it was predicted to be taking into account of the reservoir properties demonstrated in each individual zone during the flowbacks testing following fracture of the wellbore.
Some of the reduced performance can be attributed to cross flow between zones and other interference phenomena. However, the reduced performance is typically of such magnitude that all of the reduction cannot be attributable to cross flow.
In various situations, a more significant cause of production impairment is damage to the formation that takes place during the milling of the plugs. While the use of composite versus cast iron bridge plugs has significantly reduced the time and expense required for milling, the process invariably requires circulation of fluids and managing the well bore pressures in a way that results in contamination of various production zones of the reservoir with well bore fluids, such that the effective permeability of the zones is reduced. This is often thought of as slate damage. In essence, the process of removing the plugs can reverse much of the productivity improvements provided by the initial fracture stimulation.
Multiple valve assemblies may be used in coordination with multiple zones of production. In one embodiment, an individual zone of production can be completed and isolated before working on another zone. Criteria utilized for determining the sequence of production may include formation pressures, production rates, and recovery from each zone as disclosed in U.S. Pat. No. 6,808,020.
Once a zone has been completed, completion fluids within the wellbore can leak off into the formation in a process commonly known as “fluid loss”. The wellbore may fill with formation fluids as a result of the reduction of hydrostatic pressure on the completed zone. A blow-out may occur if fluid loss occurs during completion activities. Fluid may be added to the wellbore to maintain hydrostatic pressure, as disclosed in U.S. 6,808,020.
The purpose of cementing the casing is to provide a seal between zones since the drilling of the hole breaks through the natural barriers. Perforations (from sharper changes) provide communication through casing and cement to formation. In High Perm reservoirs, perforation alone is enough to put the well on production.
In Low Perm reservoirs (tight reservoirs), one creates additional exposure by creating fractures in the rock. That can extend far from the well bore. Typically, the fracture (or frac) fluid contains proppant solids designed to hold the fractures open (propped open) so that production fluids flow easily through the fracture back into the well bore.
In instances where fracturing is not necessary, perforation quality is critical because the perforation needs to cut through the casing, the cement, and extend into the formation enough to pass any formation damage that occurs during drilling the well.
Commonly, in various embodiments, all that is needed to fracture stimulate is the perforation job to provide communication from the wellbore to the reservoir. Once the fracture is initiated, the Frac job will typically cause the area around the plugged hole in the casing to be removed. In various further embodiments, perforation through only the casing is sufficient to allow the facture pressures to cause the cement to fail in the area about the casing perforation hole and thereby allow communication. However, in various embodiments, the fracture pressure will not be sufficient to break the cement.
Systems and processes for removing fluids from a wellbore are known in the art. Various examples of prior art systems and processes include U.S. Pat. Nos. 7,426,938; 7,114,558; 7,059,407; 6,957,701; 6,808,020; 6,732,803; 6,631,772; 6,575,247; 6,520,255; 6,065,536; 5,673,658; 4,852,391; 4,559,786; 4,557,325; 2,067,408; 2,925,775; 2,968,243; 2,986,214; 3,028,914; 3,111,988; 3,118,501; 3,366,188; 3,427,652; 3,429,384; 3,547,198; 3,662,833; 3,712,379; 3,739,723; 3,874,461; 4,102,401; 4,113,314; 4,137,182; 4,139,060; 4,244,425; 4,415,035; 4,637,468; 4,671,352; 4,702,316; 4,776,393; 4,809,781; 4,860,831; 4,865,131; 4,867,241; 5,025,861; 5,103,912; 5,131,472; 5,161,618; 5,309,995; 5,314,019; 5,353,875; 5,390,741; 5,485,882; 5,513,703; 5,579,844; 5,598,891; 5,669,448; 5,704,426; 5,755,286; 5,803,178; 5,812,068; 5,832,998; 5,845,712; 5,865,252; 5,890,536; 5,921,318; 5,934,377; 5,947,200; 5,954,133; 5,990,051; 5,996,687; 6,003,607; 6,012,525; 6,053,248; 6,098,713; 6,116,343; 6,131,662; 6,186,227; 6,186,230; 6,186,236; 6,189,621; 6,241,013; 6,257,332; 6,257,338; 6,272,434; 6,286,598; 6,296,066; 6,394,184; 6,408,942; 6,446,727; 6,474,419; 6,488,082; 6,494,260; 6,497,284; 6,497,290; 6,543,538; 6,543,540; 6,547,011, the contents all of which are hereby incorporated by reference as if reproduced in its entirety.